Remotely controlled apparatus for downhole applications and related methods

ABSTRACT

An expandable apparatus may comprise a tubular body, a valve piston and a push sleeve. The tubular body may comprise a fluid passageway extending therethrough, and the valve piston may be disposed within the tubular body, the valve piston configured to move axially within the tubular body responsive to a pressure of drilling fluid passing through the fluid passageway and configured to selectively control a flow of fluid into an annular chamber. The push sleeve may be disposed within the tubular body and coupled to at least one expandable feature, the push sleeve configured to move axially responsive to a flow of fluid into the annular chamber extending the at least one expandable feature.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. patent application Ser. No.13/169,743, filed Jun. 27, 2011, pending, which claims the benefit ofU.S. Provisional Application Ser. No. 61/389,578, filed Oct. 4, 2010,entitled “STATUS INDICATORS FOR USE IN EARTH-BORING TOOLS HAVINGEXPANDABLE MEMBERS AND METHODS OF MAKING AND USING SUCH STATUSINDICATORS AND EARTH-BORING TOOLS,” and of U.S. Provisional ApplicationSer. No. 61/412,911, filed Nov. 12, 2010, entitled “REMOTELY CONTROLLEDAPPARATUS FOR DOWNHOLE APPLICATIONS AND RELATED METHODS,” the disclosureof each of which is hereby incorporated herein by this reference in itsentirety.

This application is related to U.S. patent application Ser. No.12/895,233, filed Sep. 30, 2010, pending, entitled “REMOTELY CONTROLLEDAPPARATUS FOR DOWNHOLE APPLICATIONS AND METHODS OF OPERATION,” whichclaims priority to U.S. Provisional Application Ser. No. 61/247,162,filed Sep. 30, 2009, entitled “REMOTELY ACTIVATED AND DEACTIVATEDEXPANDABLE APPARATUS FOR EARTH BORING APPLICATIONS,” and to U.S.Provisional Patent Application Ser. No. 61/377,146, filed Aug. 26, 2010,entitled “REMOTELY-CONTROLLED DEVICE AND METHOD FOR DOWNHOLE ACTUATION,”the disclosure of each of which is hereby incorporated herein by thisreference in its entirety.

TECHNICAL FIELD

Embodiments of the present invention relate generally to remotelycontrolled apparatus for use in a subterranean wellbore and componentstherefor. Some embodiments relate to an expandable reamer apparatus forenlarging a subterranean wellbore, some to an expandable stabilizerapparatus for stabilizing a bottom hole assembly during a drillingoperation, and other embodiments to other apparatus for use in asubterranean wellbore, and in still other embodiments to an actuationdevice and system. Embodiments additionally relate to devices andmethods for remotely detecting the operating condition of such remotelycontrolled apparatus.

BACKGROUND

Wellbores, also called boreholes, for hydrocarbon (oil and gas)production, as well as for other purposes, such as for examplegeothermal energy production, are drilled with a drill string thatincludes a tubular member (also referred to as a drilling tubular)having a drilling assembly (also referred to as the drilling assembly orbottom hole assembly or “BHA”) which includes a drill bit attached tothe bottom end thereof. The drill bit is rotated to shear ordisintegrate material of the rock formation to drill the wellbore. Thedrill string often includes tools or other devices that need to beremotely activated and deactivated during drilling operations. Suchtools and devices include, among other things, reamers, stabilizers orforce application members used for steering the drill bit. Productionwells include devices, such as valves, inflow control device, etc., thatare remotely controlled. The disclosure herein provides a novelapparatus for controlling such devices and other downhole tools ordevices.

Expandable tools are typically employed in downhole operations indrilling oil, gas and geothermal wells. For example, expandable reamersare typically employed for enlarging a subterranean wellbore. Indrilling oil, gas, and geothermal wells, a casing string (such termbroadly including a liner string) may be installed and cemented withinthe wellbore to prevent the wellbore walls from caving into the wellborewhile providing requisite shoring for subsequent drilling operations toachieve greater depths. Casing also may be installed to isolatedifferent formations, to prevent cross-flow of formation fluids, and toenable control of formation fluids and pressure as the borehole isdrilled. To increase the depth of a previously drilled borehole, newcasing is laid within and extended below the previously installedcasing. While adding additional casing allows a borehole to reachgreater depths, it has the disadvantage of narrowing the borehole.Narrowing the borehole restricts the diameter of any subsequent sectionsof the wellbore because the drill bit and any further casing must passthrough the existing casing. As reductions in the borehole diameter areundesirable because they limit the production flow rate of oil and gasthrough the borehole, it is often desirable to enlarge a subterraneanborehole to provide a larger borehole diameter for installing additionalcasing beyond previously installed casing as well as to enable betterproduction flow rates through the wellbore. A variety of approaches havebeen employed for enlarging a borehole diameter. One conventionalapproach used to enlarge a subterranean borehole includes usingeccentric and bi-center bits. For example, an eccentric bit with alaterally extended or enlarged cutting portion is rotated about its axisto produce an enlarged wellbore diameter. A bi-center bit assemblyemploys two longitudinally superimposed bit sections with laterallyoffset longitudinal axes, which produce an enlarged wellbore diameterwhen the bit is rotated.

Another conventional approach used to enlarge a subterranean wellboreincludes employing an extended bottom-hole assembly with a pilot drillbit at the distal end thereof and a reamer assembly some distance above.This arrangement permits the use of any standard rotary drill bit type,be it a rock bit or a drag bit, as the pilot bit, and the extendednature of the assembly permits greater flexibility when passing throughtight spots in the wellbore as well as the opportunity to effectivelystabilize the pilot drill bit so that the pilot hole and the followingreamer will traverse the path intended for the wellbore. This aspect ofan extended bottom hole assembly is particularly significant indirectional drilling. One design to this end includes so-called “reamerwings,” which generally comprise a tubular body having a fishing neckwith a threaded connection at the top thereof and a tong die surface atthe bottom thereof, also with a threaded connection. The uppermid-portion of the reamer wing tool includes one or more longitudinallyextending blades projecting generally radially outwardly from thetubular body, the outer edges of the blades carrying PDC cuttingelements.

As mentioned above, conventional expandable reamers may be used toenlarge a subterranean wellbore and may include blades pivotably orhingedly affixed to a tubular body and actuated by way of a pistondisposed therein. In addition, a conventional wellbore opener may beemployed comprising a body equipped with at least two hole opening armshaving cutting means that may be moved from a position of rest in thebody to an active position by exposure to pressure of the drilling fluidflowing through the body. The blades in these reamers are initiallyretracted to permit the tool to be run through the wellbore on a drillstring and once the tool has passed beyond the end of the casing, theblades are extended so the bore diameter may be increased below thecasing.

The blades of some conventional expandable reamers have been sized tominimize a clearance between themselves and the tubular body in order toprevent any drilling mud and earth fragments from becoming lodged in theclearance and binding the blade against the tubular body. The blades ofthese conventional expandable reamers utilize pressure from inside thetool to apply force radially outward against pistons which move theblades, carrying cutting elements, laterally outward. It is felt by somethat the nature of some conventional reamers allows misaligned forces tocock and jam the pistons and blades, preventing the springs fromretracting the blades laterally inward. Also, designs of someconventional expandable reamer assemblies fail to help blade retractionwhen jammed and pulled upward against the wellbore casing. Furthermore,some conventional hydraulically actuated reamers utilize expensive sealsdisposed around a very complex shaped and expensive piston, or blade,carrying cutting elements. In order to prevent cocking, someconventional reamers are designed having the piston shaped oddly inorder to try to avoid the supposed cocking, requiring matching andcomplex seal configurations. These seals are feared to possibly leakafter extended usage.

Notwithstanding the various prior approaches to drill and/or ream alarger diameter wellbore below a smaller diameter wellbore, the needexists for improved apparatus and methods for doing so. For instance,bi-center and reamer wing assemblies are limited in the sense that thepass through diameter of such tools is nonadjustable and limited by thereaming diameter. Furthermore, conventional bi-center and eccentric bitsmay have the tendency to wobble and deviate from the path intended forthe wellbore. Conventional expandable reaming assemblies, whilesometimes more stable than bi-center and eccentric bits, may be subjectto damage when passing through a smaller diameter wellbore or casingsection, may be prematurely actuated, and may present difficulties inremoval from the wellbore after actuation.

Additionally, if an operator of an expandable tool is not aware of theoperating condition of the expandable tool (e.g., whether the tool is inan expanded or retracted position), damage to the tool, drill stringand/or borehole may occur, and operating time and expenses may bewasted. In view of this, improved expandable apparatus and operatingcondition detection methods would be desirable.

BRIEF SUMMARY

In some embodiments, an expandable apparatus may comprise a tubularbody, a valve piston and a push sleeve. The tubular body may comprise afluid passageway extending therethrough, and the valve piston may bedisposed within the tubular body, the valve piston configured to moveaxially downward within the tubular body responsive to a pressure ofdrilling fluid passing through the fluid passageway and configured toselectively control a flow of fluid into an annular chamber. The pushsleeve may be disposed within the tubular body and coupled to at leastone expandable feature, the push sleeve configured to move axiallyresponsive to the flow of fluid into the annular chamber extending theat least one expandable feature.

In further embodiments, a method of operating an expandable apparatusmay comprise positioning an expandable apparatus in a borehole,directing a fluid flow through a fluid passageway of a tubular body ofthe expandable apparatus, and moving a valve piston axially relative tothe tubular body in response to fluid flow through the fluid passagewayto open at least one fluid port to an annular chamber. The method mayfurther comprise moving a push sleeve axially relative to the tubularbody with a fluid flow directed into the annular chamber through the atleast one fluid port, and extending at least one expandable featurecoupled to the push sleeve.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a side view of an embodiment of an expandable apparatus of thedisclosure.

FIG. 2 shows a transverse cross-sectional view of the expandableapparatus as indicated by section line 2-2 in FIG. 1.

FIG. 3 shows a longitudinal cross-sectional view of the expandableapparatus shown in FIG. 1 in a neutral position.

FIG. 4 shows a longitudinal cross-sectional view of the expandableapparatus shown in FIG. 1 in a locked closed position.

FIG. 5 shows a longitudinal cross-sectional view of the expandableapparatus shown in FIG. 1 in a locked opened position.

FIGS. 6A and 6B show a longitudinal cross-sectional detail view of avalve piston and valve housing including a collet.

FIGS. 7A and 7B show a longitudinal cross-sectional detail view of avalve piston and valve housing including a detent.

FIGS. 8A and 8B show a longitudinal cross-sectional detail view of aportion of an expandable apparatus including a sealing member totemporarily close nozzle ports of a push sleeve.

FIG. 9A shows a longitudinal cross-sectional view of an expandableapparatus including fluid ports on either side of a necked down orifice.

FIG. 9B shows an enlarged cross-sectional view of the expandableapparatus shown in FIG. 9A and with the blades expanded.

FIG. 10 is an elevation view of a drilling system including anexpandable apparatus, according to an embodiment of the disclosure.

FIGS. 11A and 11B show cross-sectional details views of a valve pistonand valve housing including a dashpot.

FIGS. 12A-12C show cross-sectional views of a valve piston and valvehousing including a track and pin arrangement.

FIG. 13 shows an enlarged view of a fluid port in the valve piston ofFIG. 12A-12C.

FIGS. 14A and 14B show cross-sectional detail views of a chevron sealassembly located at an interface of a valve piston and valve housing ofan expandable device such as shown in FIGS. 3-5.

FIG. 15 shows an enlarged cross-sectional view of a bottom portion of anexpandable apparatus, such as shown in FIGS. 1-5, including a statusindicator and in a retracted configuration.

FIG. 16 shows an enlarged cross-sectional view of the bottom portion ofthe expandable apparatus shown in FIG. 15 when the expandable reamerapparatus is in an extended configuration.

FIG. 17 shows an enlarged cross-sectional view of the status indicatoras shown in FIG. 15.

FIG. 18 shows an enlarged cross-sectional view of the status indicatoras shown in FIG. 16.

FIGS. 19-23 show longitudinal side views of additional embodiments ofstatus indicators.

FIG. 24 shows a simplified graph of a pressure of drilling fluid withina valve piston as a function of a distance by which the valve pistontravels relative to a status indicator.

DETAILED DESCRIPTION

The illustrations presented herein are, in some instances, not actualviews of any particular expandable apparatus or component thereof, butare merely idealized representations that are employed to describeembodiments of the disclosure. Additionally, elements common betweenfigures may retain the same numerical designation.

Various embodiments of the disclosure are directed to expandableapparatus. By way of example and not limitation, an expandable apparatusmay comprise an expandable reamer apparatus, an expandable stabilizerapparatus or similar apparatus. As described in more detail herein,expandable apparatus of the present disclosure may be remotelyselectable between at least two operating positions while located withina borehole. It may be important for an operator who is controlling orsupervising the operation of the expandable apparatus to know thecurrent operating position of the tool in the borehole, such as toprevent damage to the tool, the borehole, or other problems. In view ofthis, embodiments of the present disclosure include features thatfacilitate the remote detection of a change in operating position of theexpandable apparatus (e.g., when the expandable apparatus changes from aretracted position to an expanded position).

FIG. 1 illustrates an expandable apparatus 100 according to anembodiment of the disclosure comprising an expandable reamer. Theexpandable reamer may be similar to the expandable apparatus describedin U.S. Patent Publication No. 2008/0128175, filed Dec. 3, 2007 andentitled “Expandable Reamers for Earth Boring Applications,” the entiredisclosure of which is incorporated herein by this reference.

The expandable apparatus 100 may include a generally cylindrical tubularbody 105 having a longitudinal axis L. The tubular body 105 of theexpandable apparatus 100 may have a lower end 110 and an upper end 115.The terms “lower” and “upper,” as used herein with reference to the ends110, 115, refer to the typical positions of the ends 110, 115 relativeto one another when the expandable apparatus 100 is positioned within awellbore. The lower end 110 of the tubular body 105 of the expandableapparatus 100 may include a set of threads (e.g., a threaded male pinmember) for connecting the lower end 110 to another section of a drillstring or another component of a bottom-hole assembly (BHA), such as,for example, a drill collar or collars carrying a pilot drill bit fordrilling a wellbore. Similarly, the upper end 115 of the tubular body105 of the expandable apparatus 100 may include a set of threads (e.g.,a threaded female box member) for connecting the upper end 115 toanother section of a drill string or another component of a bottom-holeassembly (BHA) (e.g., an upper sub).

At least one expandable feature may be positioned along the expandableapparatus 100. For example, three expandable features configured assliding cutter blocks or blades 120, 125, 130 (see FIG. 2) may bepositionally retained in circumferentially spaced relationship in thetubular body 105 as further described below and may be provided at aposition along the expandable apparatus 100 intermediate the lower end110 and the upper end 115. The blades 120, 125, 130 may be comprised ofsteel, tungsten carbide, a particle-matrix composite material (e.g.,hard particles dispersed throughout a metal matrix material), or othersuitable materials as known in the art. The blades 120, 125, 130 areretained in an initial, retracted position within the tubular body 105of the expandable apparatus 100 as illustrated in FIG. 3, but may bemoved responsive to application of hydraulic pressure into the extendedposition (shown in FIG. 4) and moved into a retracted position (shown inFIG. 5) when desired, as will be described herein. The expandableapparatus 100 may be configured such that the blades 120, 125, 130engage the walls of a subterranean formation surrounding a wellbore inwhich the expandable apparatus 100 is disposed to remove formationmaterial when the blades 120, 125, 130 are in the extended position, butare not operable to so engage the walls of a subterranean formationwithin a wellbore when the blades 120, 125, 130 are in the retractedposition. While the expandable apparatus 100 includes three blades 120,125, 130, it is contemplated that one, two or more than three blades maybe utilized to advantage. Moreover, while the blades 120, 125, 130 aresymmetrically circumferentially positioned axially along the tubularbody 105, the blades may also be positioned circumferentiallyasymmetrically as well as asymmetrically along the longitudinal axis Lin the direction of either end 110 or 115.

The expandable apparatus 100 may optionally include a plurality ofstabilizer blocks 135, 141, 145. In some embodiments, a mid stabilizerblock 141 and a lower stabilizer block 145 may be combined into aunitary stabilizer block. The stabilizer blocks 135, 141, 145 mayfacilitate the centering of the expandable apparatus 100 within theborehole while being run into position through a casing or liner stringand also while drilling and reaming the wellbore. In other embodiments,no stabilizer blocks may be employed. In such embodiments, the tubularbody 105 may comprise a larger outer diameter in the longitudinalportion where the stabilizer blocks are shown in FIG. 1 to provide asimilar centering function as provided by the stabilizer blocks.

An upper stabilizer block 135 may be used to stop or limit the forwardmotion of the blades 120, 125, 130 (see also FIG. 3), determining theextent to which the blades 120, 125, 130 may engage a bore hole whiledrilling. The upper stabilizer block 135, in addition to providing aback stop for limiting the lateral extent of the blades when extended,may provide for additional stability when the blades 120, 125, 130 areretracted and the expandable apparatus 100 of a drill string ispositioned within a bore hole in an area where an expanded hole is notdesired while the drill string is rotating. Advantageously, the upperstabilizer block 135 may be mounted, removed and/or replaced by atechnician, particularly in the field, allowing the extent to which theblades 120, 125, 130 engage the bore hole to be readily increased ordecreased to a different extent than illustrated. Optionally, it isrecognized that a stop associated on a track side of the upperstabilizer block 135 may be customized in order to arrest the extent towhich the blades 120, 125, 130 may laterally extend when fullypositioned to the extended position along the blade tracks 220. Thestabilizer blocks 135, 140, 145 may include hardfaced bearing pads (notshown) to provide a surface for contacting a wall of a bore hole whilestabilizing the expandable apparatus 100 therein during a drillingoperation.

FIG. 2 is a cross-sectional view of the expandable apparatus 100 shownin FIG. 1 taken along section line 2-2 shown therein. As shown in FIG.2, the tubular body 105 encloses a fluid passageway 205 that extendslongitudinally through the tubular body 105. The fluid passageway 205directs fluid substantially through an inner bore 210 of a push sleeve215. To better describe aspects of this embodiment, blades 125 and 130are shown in FIG. 2 in the initial or retracted positions, while blade120 is shown in the outward or extended position. The expandableapparatus 100 may be configured such that the outermost radial orlateral extent of each of the blades 120, 125, 130 is recessed withinthe tubular body 105 when in the initial or retracted positions so itmay not extend beyond the greatest extent of outer diameter of thetubular body 105. Such an arrangement may protect the blades 120, 125,130, a casing, or both, as the expandable apparatus 100 is disposedwithin the casing of a wellbore, and may allow the expandable apparatus100 to pass through such casing within a wellbore. In other embodiments,the outermost radial extent of the blades 120, 125, 130 may coincidewith or slightly extend beyond the outer diameter of the tubular body105. As illustrated by blade 120, the blades 120, 125, 130 may extendbeyond the outer diameter of the tubular body 105 when in the extendedposition, to engage the walls of a wellbore in a reaming operation.

FIG. 3 is another cross-sectional view of the expandable apparatus 100shown in FIGS. 1 and 2 taken along section line 3-3 shown in FIG. 2.Referring to FIGS. 2 and 3, the tubular body 105 positionally retainsthree sliding cutter blocks or blades 120, 125, 130 in three respectiveblade tracks 220. The blades 120, 125, 130 each carry a plurality ofcutting elements 225 for engaging the material of a subterraneanformation defining the wall of an open wellbore when the blades 120,125, 130 are in an extended position. The cutting elements 225 may bepolycrystalline diamond compact (PDC) cutters or other cutting elementsknown to a person of ordinary skill in the art and as generallydescribed in U.S. Pat. No. 7,036,611, the disclosure of which isincorporated herein in its entirety by this reference.

Referring to FIG. 3, the blades 120, 125, 130 (as illustrated by blade120) may be hingedly coupled to the push sleeve 215. The push sleeve 215may be configured to slide axially within the tubular body 105 inresponse to pressures applied to one end or the other, or both. In someembodiments, the push sleeve 215 may be disposed in the tubular body 105and may be configured similar to the push sleeve described by U.S.Patent Publication No. 2008/0128175 referenced above and biased by aspring as described therein. However, as illustrated in FIG. 3, theexpandable apparatus 100 described herein does not require the use of acentral stationary sleeve and, rather, the inner bore 210 of the pushsleeve 215 may form the fluid passageway.

As shown in FIG. 3, the push sleeve 215 may comprise an upper surface310 and a lower surface 315 at opposing longitudinal ends. Such a pushsleeve 215 may be configured and positioned so that the upper surface310 comprises a smaller annular surface area than the lower surface 315to create a greater force on the lower surface 315 than on the uppersurface 310 when a like pressure is exerted on both surfaces by apressurized fluid, as described in more detail below. Before drilling,the push sleeve 215 may be biased toward the bottom end 110 of theexpandable apparatus 100 by a first spring 133. The first spring 133 mayresist motion of the push sleeve 215 toward the upper end 115 of theexpandable apparatus 100, thus biasing the blades 120, 125, 130 to theretracted position. This facilitates the insertion and/or removal of theexpandable apparatus 100 from a wellbore without the blades 120, 125,130 engaging walls of a subterranean formation or casing defining thewellbore.

The push sleeve 215 may further include a plurality of nozzle ports 335that may communicate with a plurality of nozzles 336 for directing adrilling fluid toward the blades 120, 125, 130.

As shown in FIGS. 3-5, the plurality of nozzle ports 335 may beconfigured such that they are always in communication with the pluralityof nozzles 336. In other words, the plurality of nozzle ports 335 andcorresponding nozzles 336 may be in a continuously open positionregardless of a position of the blades 120, 125, 130. Having the nozzleports 335 and the corresponding nozzles 336 in a continuously openposition may help to prevent any blockages from forming in the nozzleports 335 and the corresponding nozzles 336. Furthermore, having thenozzle ports 335 and the corresponding nozzles 336 in a continuouslyopen position may help keep the blades 120, 125, 130 and an exterior ofthe expandable apparatus 100 cool while in a wellbore at all times.However, in some embodiments, the nozzle ports 335 may be temporarilyclosed, such as to produce a detectable pressure change of the drillingfluid, as will be described in further detail herein with reference toFIG. 8.

Referring again to FIG. 3, a valve piston 216 may also be disposedwithin the expandable apparatus 100 and configured to move axiallywithin the expandable apparatus 100 in response to fluid pressuresapplied to the valve piston 216. Before expansion of the expandableapparatus 100, the valve piston 216 may be biased toward the upper end115 of the expandable apparatus 100, such as by a spring 134. Theexpandable apparatus 100 may also include a stationary valve housing 144(e.g., stationary relative to the tubular body 105) axially surroundingthe valve piston 216. The valve housing 144 may include an upper portion146 and a lower portion 148. The lower portion 148 of the valve housing144 may include at least one fluid port 140 which is configured toselectively align with at least one fluid port 129 formed in the valvepiston 216. When the at least one fluid port 129 of the valve piston 216is aligned with the at least one fluid port 140 of the lower portion 148of the valve housing 144, fluid may flow from the fluid passageway 205to a lower annular chamber 345 between the inner sidewall of the tubularbody 105 and the outer surfaces of the valve housing 144, and incommunication with the lower surface 315 of the push sleeve 215. Infurther embodiments, the valve piston 216 may not include a fluid port129, but may otherwise move longitudinally relative to the valve housing144 and leave the at least one fluid port 140 unobstructed to allowfluid flow therethrough, such as shown in FIGS. 9A and 9B.

In operation, the push sleeve 215 may be originally positioned towardthe lower end 110 with the at least one fluid port 129 of the valvepiston 216 misaligned with the at least one fluid port 140 of the lowerportion 148 of the valve housing 144. This original position may also bereferred to as a neutral position and is illustrated in FIG. 3. In theneutral position, the blades 120, 125, 130 are in the retracted positionand are maintained that way by the first spring 133 biasing the pushsleeve 215 towards the bottom end 110 of the expandable apparatus 100without the flow of any fluid. A fluid, such as a drilling fluid, may beflowed through the fluid passageway 205 in the direction of arrow 405.As the fluid flows through the fluid passageway 205, the fluid exerts aforce on a surface 136 of the valve piston 216 in addition to the fluidbeing forced through a reduced area formed by a nozzle 202 coupled tothe valve piston 216. When the pressure on the surface 136 and thenozzle 202 becomes great enough to overcome the biasing force of thesecond spring 134, the valve piston 216 moves axially toward the bottomend 110 of expandable apparatus 100 as shown in FIG. 4. As shown in FIG.4, although the valve piston has moved axially toward the bottom end 100of the expandable apparatus 100, the at least one fluid port 129 of thevalve piston 216 remains misaligned with the at least one fluid port 140of the lower portion 148 of the valve housing 144. This position, asillustrated in FIG. 4, may be referred to as the locked closed position.In the locked closed position, the blades will remain in the fullyretracted position while fluid is flowed through the fluid passageway205 as the position of the valve piston 216 may be mechanically held,such as by a pin and pin track mechanism further described herein withreference to FIGS. 12A-12C.

When the at least one fluid port 129 of the valve piston 216 and the atleast one fluid port 140 of the lower portion 148 of the valve housing144 are selectively aligned, as will be described in greater detailbelow, the fluid flows from the fluid passageway 205 into the annularchamber 345, causing the fluid to pressurize the annular chamber 345 andexert a force on the lower surface 315 of the push sleeve 215. Asdescribed above, the lower surface 315 of the push sleeve 215 has alarger surface area than the upper surface 310. Therefore, with equal orsubstantially equal pressures applied to the upper surface 310 and lowersurface 315 by the fluid, the force applied on the lower surface 315,having the larger surface area, will be greater than the force appliedon the upper surface 310, having the smaller surface area, by virtue ofthe fact that force is equal to the pressure applied multiplied by thearea to which it is applied. When the pressure on the lower surface 315is great enough to overcome the force applied by the first spring 133,the resultant net force is upward and causes the push sleeve 215 toslide upward, thereby extending the blades 120, 125, 130, as shown inFIG. 5, which is also referred to as the locked open position.

In some embodiments, a resettable check valve may be included, such aslocated within the at least one fluid port 140, that may prevent fluidfrom flowing through the at least one fluid port 140 until apredetermined pressure is achieved. After the at least one fluid port129 of the valve piston 216 and the at least one fluid port 140 of thelower portion 148 of the valve housing 144 are selectively aligned,activation may be delayed until a predetermined fluid pressure isachieved. In view of this, a predetermined fluid pressure may beachieved prior to movement of the blades 120, 125, 130 to an expandedposition. A specific pressure, or a change in pressure, may then bedetected, such as by a pressure sensor as described further herein, tosignal to an operator that the blades 120, 125, 130 have moved to theexpanded position. By including the check valve, the peak pressureachieved and the change in pressure upon activation may be increased andthe measurement of the peak pressure or the change in pressure may bemore readily ascertained and may be more reliable in indicating that theblades 120, 125, 130 have moved to an extended position.

In further embodiments, a collet 400 may be utilized to maintain thevalve piston 216 in a selected axial position until a predeterminedaxial force is applied (e.g., when a predetermined fluid pressure orfluid flow is achieved), as shown in FIGS. 6A and 6B, which mayfacilitate at least one of a peak pressure and a change in pressure thatmay be reliably identified via a pressure sensor and utilized to alertan operator that the blades 120, 125, 130 have moved to an extendedposition. The collet 400 may comprise a plurality of end segments 402coupled to biasing members 404 that may bias the end segments 402radially inward. The valve piston 216 may include a shoulder 410 and theend segments 402 of the biased collet 400 may be positioned over theshoulder 410, when the expandable apparatus 100 is in a neutralposition, as shown in FIG. 6A. Upon applying a predetermined axial forceto the valve piston 216 (e.g., when a predetermined fluid pressure orfluid flow is achieved), the shoulder 410 may push against the endsegments 402 of the collet 400 and overcome the force applied by thebiasing members 404 of the collet 400 and push the end segments 402radially outward, as shown in FIG. 6B. In view of this, the valve piston216 may not move out of the closed position until an axial force appliedto the valve piston 216 exceeds a threshold amount. By maintaining theposition of the valve piston 216 until a predetermined amount of forceis applied, a fluid flow and pressure required to move the shoulder 410of valve piston 216 past the end segments 402 of the collet 400 may begreater than is required to move the valve piston 216 after the endsegments 402 have been pushed radially outward past the shoulder 410. Inview of this, at least one of a predetermined fluid flow and pressuremay be achieved prior to movement of the blades 120, 125, 130 (FIG. 2)to an expanded position. A specific pressure, or a change in pressure,may then be detected and utilized to signal to an operator that theblades 120, 125, 130 have moved to an expanded position.

Additionally, a collet 400 may also be utilized to maintain the valvepiston 216 in an axial position corresponding to the fully expandedposition of the blades 120, 125, 130. In view of this, at least onecollet 400 may be positioned relative to at least one shoulder 410 toresist movement of the valve piston 216 from one or more of a firstaxial position corresponding to a fully retracted position of the blades120, 125, 130 (e.g., a relatively low drilling fluid pressure state),and a second axial position corresponding to a fully expanded positionof the blades 120, 125, 130 (e.g., a relatively high drilling fluidpressure state).

In further embodiments, a detent 500 may be utilized to maintain thevalve piston 216 in a selected axial position until a predeterminedaxial force is applied (e.g., when a predetermined pressure isachieved), as shown in FIGS. 7A and 7B. The detent 500 may comprise amovable protrusion 502 biased toward the valve piston 216, by a biasingmember 506, such as by a spring (e.g., a helical compression spring or astack of Belleville washers). The valve piston 216 may include a cavity,such as a groove 504 that may extend circumferentially around the valvepiston 216, and the movable protrusion 502 may be positioned at leastpartially within the cavity (e.g., groove 504) when the device is in aneutral position, as shown if FIG. 7A. Upon applying a predeterminedaxial force to the valve piston 216, the groove 504 may push against themoveable protrusion 502 of the detent 500 and overcome the force appliedby the biasing members 506 of the detent 500 and push the movableprotrusion 502 out of the groove 504, as shown in FIG. 7B. In view ofthis, the valve piston 216 may not move out of the neutral positionuntil an axial force applied to the valve piston 216 exceeds a thresholdamount. By maintaining the position of the valve piston 216 until apredetermined amount of force is applied, a fluid flow and pressurerequired to move the groove 504 of the valve piston 216 past the movableprotrusion 502 of the detent 500 may be greater than is required to movethe valve piston 216 after the movable protrusion 502 has been pushedpast the groove 504. In view of this, a predetermined fluid pressure maybe achieved prior to movement of the blades 120, 125, 130 (FIG. 2) to anexpanded position. In view of this, at least one of a predeterminedfluid flow and pressure may be achieved prior to movement of the blades120, 125, 130 (FIG. 2) to an expanded position. A specific pressure, ora change in pressure, may then be detected and utilized to signal to anoperator that the blades 120, 125, 130 have moved to an expandedposition.

Additionally, a detent 500 may also be utilized to maintain the valvepiston 216 in an axial position corresponding to the fully expandedposition of the blades 120, 125, 130. In view of this, at least onedetent 500 may be positioned relative to at least one groove 504 toresist movement of the valve piston 216 from one or more of a firstaxial position corresponding to a fully retracted position of the blades120, 125, 130 (e.g., a relatively low drilling fluid pressure state),and a second axial position corresponding to a fully expanded positionof the blades 120, 125, 130 (e.g., a relatively high drilling fluidpressure state).

In further embodiments, the plurality of nozzle ports 335 may beconfigured such that they are in communication with the plurality ofnozzles except for when the blades are positioned in a less than fullyexpanded position, which may facilitate at least one of a peak pressureand a change in pressure that may be reliably identified via a pressuresensor and utilized to alert an operator that the blades 120, 125, 130have moved to an extended position. For example, the plurality of nozzleports 335 and corresponding nozzles may be closed to fluid communicationjust before the blades 120, 125, 130 are in the fully expanded position,such as by passing a sealing member 600 as shown in FIG. 8A. Thistemporary closing of the nozzle ports as the tool transitions betweenthe retracted position and the fully expanded position may provide asignificant and reliably detectable pressure change, which may bedetected to signal to an operator that the blades have moved to thefully expanded position. For another example, the plurality of nozzleports 335 and corresponding nozzles may be closed to fluid communicationwhen the blades 120, 125, 130 are in the fully retracted position by asealing member 610 and open to fluid communication when the blades arein the fully expanded position, as shown in FIG. 8B.

In yet further embodiments, an expandable apparatus 1100 may includefluid ports 1320 and 1321 on either side of a necked down orifice 1325,as shown in FIGS. 9A and 9B. When one of the fluid ports 1320, 1321 isclosed, as shown in FIG. 9A, any fluid passing through the tubular bodywill be directed through the necked down orifice 1325. With both thefluid ports 1320 and 1321 open to an upper annular chamber 1330, asshown in FIG. 9B, the fluid exits the upper fluid port 1320 above thenecked down orifice 1325, into the upper annular chamber 1330 and thenback into the fluid passageway 205 (see FIG. 2) through the lower fluidport 1321 below the necked down orifice 1325. This increases the totalflow area through which the drilling fluid may flow (e.g., through thenecked down orifice 1325 and through the upper annular chamber 1330 byway of the fluid ports 1320 and 1321. The increase in the total flowarea results in a substantial reduction in fluid pressure above thenecked down orifice 1325.

This change in pressure resulting from the activation of the expandableapparatus 1100 may be utilized to facilitate the detection of theoperating condition of the expandable apparatus 1100. The change inpressure may be detected by a fluid pressure monitoring device, whichmay alert the operator as to the change in operating conditions of theexpandable apparatus 1100. The change in pressure may be identified indata comprising the monitored standpipe pressure, and may indicate tothe operator that the blades 120, 125, 130 (see FIG. 2) of theexpandable apparatus 1100 are in the expanded position. In other words,the change in pressure may provide a signal to the operator that theblades 120, 125, 130 (see FIG. 2) have been expanded for engaging theborehole.

In at least some embodiments, the change in pressure may be a pressuredrop of between about 140 psi and about 270 psi facilitated by theopening of the fluid ports 1320 and 1321. In one non-limiting example,the push sleeve 215 (see FIG. 2) may comprise an inner bore 210 (seeFIG. 2) having a diameter of about 2.25 inches (about 57.2 mm) and thefluid ports 1320 and 1321 may be about 2 inches (50.8 mm) long and about1 inch (25.4 mm) wide. In such an embodiment, a necked down orifice 1325comprising an inner diameter of about 1.625 inches (about 41.275 mm) mayresult in a drop in the monitored standpipe pressure of about 140 psi(about 965 kPa), assuming there are no nozzles, (the nozzles beingoptional according to various embodiments). In another example of suchan embodiment, a necked down orifice 1325 comprising an inner diameterof about 1.4 inches (about 35.56 mm) may result in a drop in themonitored standpipe pressure of about 269 psi (about 1.855 MPa).

In additional embodiments, an acoustic sensor 1500 may be coupled to adrill string 1502, such as at a location outside of a borehole 1504, andin communication with a computer 1506, as shown in FIG. 10. The acousticsensor 1500 may detect pressure waves (i.e., sound waves) that may betransmitted through the drill string 1502. When the expandable apparatus100 is activated, and the blades 120, 125, 130 are moved to the expandedposition, components of the expandable apparatus may impact othercomponents of the expandable apparatus 100, such as shown in FIG. 5. Forexample, the blades 120, 125, 130 may impact stabilizer blocks 135. Suchan impact may cause pressure waves to travel through the drill string1502 which may be detected by the acoustic sensor 1500. The acousticsensor 1500 may then transmit a signal to the computer 1506corresponding to the detected pressure wave and the operator may besignaled that the blades 120, 125, 130 have moved to an expandedposition.

Additionally, a pressure sensor, such as a pressure transducer, may beincluded within the drill string 1502, or elsewhere in the flow line ofthe drilling fluid, and may be in communication with the computer 1506.Pressure measurements may then be taken over a period of time andtransmitted to the computer. The pressure measurements may then becompared, such as by plotting as a function of time, by the computer andthe measured change in pressure over time may be utilized to determinethe operating condition of the expandable apparatus 100, such as if theblades 120, 125, 130 have moved to an expanded position. By utilizing acomparison over time, even if a measured peak pressure that correspondsto a change in the operating condition of the expandable apparatus isrelatively small compared to a baseline measurement, the comparison ofpressures over time may provide an indication of a pressure change andbe utilized to alert an operator of a change in the operating conditionof the tool.

In view of this, one or both of a pressure sensor and an acoustic sensor1500 may be coupled to the computer 1506 and the movement of the blades120, 125, 130 to one of the expanded position and the retracted positionmay be reliably detected and communicated to an operator.

In yet further embodiments, a dashpot 1600 may be utilized to slow theaxial displacement of a valve piston 216 in at least one direction, asshown in FIGS. 11A and 11B. The dashpot 1600 may comprise a fluid filledcavity, such as an annular cavity including a portion 1602 of the valvepiston 216 therein defining a first fluid reservoir 1604 and a secondfluid reservoir 1606. The portion 1602 of the valve piston 216 mayinclude one or more apertures 1608 formed therein to allow the fluid toflow between the first fluid reservoir 1604 and the second fluidreservoir 1606. The apertures 1608 may be selectively sized, and fluidproperties (e.g., viscosity) of the fluid contained in the first andsecond fluid reservoirs 1604 and 1606, may be selected to control a flowrate between the first fluid reservoir 1604 and the second fluidreservoir 1606, and thus control the actuation speed. By slowing theaxial movement of the valve piston 216 with the dashpot 1600, theactuation may be delayed, and an increased fluid pressure in thestandpipe may be achieved. Additionally, the duration of a change influid pressure may be increased. At least one of a specific pressure anda change in pressure may then be detected and utilized to signal to anoperator that the blades 120, 125, 130 of the expandable apparatus 100have moved to one of an expanded position and a retracted position.

In order to retract the blades 120, 125, 130, referring again to FIGS.3-5, the at least one fluid port 129 of the valve piston 216 and the atleast one fluid port 140 of the lower portion 148 of the valve housing144 may be selectively misaligned to inhibit the fluid from flowing intothe annular chamber 345 and applying a pressure on the lower surface 315of the push sleeve 215. When the at least one fluid port 129 of thevalve piston 216 and the at least one fluid port 140 of the lowerportion 148 of the valve housing 144 are selectively misaligned, avolume of drilling fluid may remain trapped in the lower chamber 345. Atleast one pressure relief nozzle 350 may accordingly be provided,extending through the sidewall of the tubular body 105 to allow thedrilling fluid to escape from the annular chamber 345 and into an areabetween the wellbore wall and the expandable apparatus 100. The at leastone pressure relief nozzle 350 may be always open or open uponapplication of a pressure differential, such as a check valve, and,thus, may also be referred to as a pressure release nozzle or a bleednozzle. The one or more pressure relief nozzles 350 may comprise arelatively small flow path so that a significant amount of pressure isnot lost when the fluid ports 129, 140 are aligned and the drillingfluid fills the annular chamber 345. By way of example and notlimitation, at least one embodiment of the pressure relief nozzle 350may comprise a flow path of about 0.125 inch (about 3.175 mm) indiameter. In some embodiments, the pressure relief nozzle 350 maycomprise a carbide flow nozzle. The size and/or number of the pressurerelief nozzles 350 utilized may be selected to achieve a detectablechange in standpipe pressure upon activation. For example, theutilization of a single pressure relief nozzle 350 having an openingdiameter of about one-quarter (¼) inch (about 6.35 mm) may provide achange in standpipe pressure of about 80 psi (about 550 kPa). However,some sensors may be unreliable in detecting a pressure change of about80 psi (about 550 kPa) in the standpipe. In view of this, the sizeand/or number of pressure relief nozzles 350 may be increased to providea larger change in standpipe pressure and provide a reliably detectablepressure signal to alert an operator as to the operating condition ofthe expandable apparatus 100. For example, in some embodiments, a changein standpipe pressure greater than about 100 psi (about 690 kPa) may bereliably detectable by a pressure sensor located in the standpipe, andthe size and number of pressure relief nozzles 350 may be selected toachieve a change in standpipe pressure greater than about 100 psi (about690 kPa) upon activation. In further embodiments, a change in standpipepressure greater than about 150 psi (about 1.03 MPa) may be reliablydetectable by a pressure sensor located in the standpipe and the sizeand number of pressure relief nozzles 350 may be selected to achieve achange in standpipe pressure greater than about 150 psi (about 1.03 MPa)upon activation. In some embodiments, two pressure relief nozzles 350,each having an opening diameter of about one-quarter (¼) inch (about6.35 mm) may be utilized and may provide a change in standpipe pressureof about 200 psi (about 1.38 MPa). In additional embodiments, a pressurerelief nozzle 350 may be selected to have an opening diameter greaterthan about one-quarter (¼) inch (about 6.35 mm), such as an openingdiameter of about 10/32 inch (about 8 mm) or larger.

In addition to the one or more pressure relief nozzles 350, at least onehigh pressure release device 355 may be provided to provide pressurerelease should the pressure relief nozzle 350 fail (e.g., becomeplugged). The at least one high pressure release device 355 maycomprise, for example, a backup burst disk, a high pressure check valve,or other device. The at least one high pressure release device 355 maywithstand pressures up to about five thousand pounds per square inch(5000 psi). In at least some embodiments, a screen (such as similar toscreen 1900 shown in FIG. 13) may be positioned over the at least onehigh pressure release device 355 to prevent solid debris from damagingcomponents (e.g. such as a backup burst disc, of the at least one highpressure release device 355.

As previously discussed with reference to FIGS. 3-5, the position of thevalve piston 216 may be mechanically maintained relative to the valvehousing 144, such as in one of a neutral position, a locked openposition and a locked closed position. FIGS. 12A-12C illustrate a pinand pin track system for such mechanical operation of the valve. Themechanically operated valve comprises the valve piston 216 and the valvehousing 144, which are coupled via a pin 1700 and a pin track 1702configuration.

For example, the valve piston 216 may comprise a pin track 1702 formedin an outer surface thereof and configured to receive one or more pins1700 on an inner surface of the valve housing 144. Alternatively, inother embodiments, the valve piston 216 may comprise one or more pins onthe outer surface thereof (not shown) and the valve housing 144 maycomprise a pin track formed in an inner surface for receiving the one ormore pins of the valve piston 216. In some embodiments, the pin track1702 may have what is often referred to in the art as a “J-slot”configuration.

In operation, the valve piston 216 may be biased by the second spring134 exerting a force in the upward direction. The valve piston 216 maybe configured with at least a portion having a reduced inner diameter,such as the nozzle 202, providing a constriction to downward flow ofdrilling fluid. When a drilling fluid flows through the valve piston 216and the reduced inner diameter thereof, the pressure above theconstriction created by the reduced inner diameter may be sufficient toovercome the upward force exerted by the second spring 134, causing thevalve piston 216 to travel downward and the second spring 134 tocompress. If the flow of drilling fluid is eliminated or reduced below aselected threshold, the upward force exerted by the second spring 134may be sufficient to move the valve piston 216 at least partiallyupward.

Referring to FIGS. 12A-12C, one or more pins, such as pin 1700 carriedby the valve housing 144, is received by the pin track 1702. The valvepiston 216 is longitudinally and rotationally guided by the engagementof one or more pins 1700 with pin track 1702. For example, when there isrelatively little or no fluid flow through the valve piston 216, theforce exerted by the second spring 134 biases the valve piston 216upward and the pin 1700 rests in a first lower hooked portion 1704 ofthe pin track 1702, as shown in FIG. 12A. This corresponds to theneutral position of the reamer apparatus shown in FIG. 3. When drillingfluid is flowed through the valve piston 216 at a sufficient flow rateto overcome the force exerted by the second spring 134 and the valvepiston 216 is biased downward, the track 1702 moves along the pin 1700until pin 1700 comes into contact with the upper angled sidewall 1706 ofthe pin track 1702. Movement of the valve piston 216 continues as pin1700 is engaged by the upper angled sidewall 1706 until the pin 1700sits in a first upper hooked portion 1708. As the track 1702 and itsupper angled sidewall 1706 is engaged by pin 1700, the valve piston 216is forced to rotate, assuming the valve housing 144 to which the pin1700 is attached is fixed within the tubular body 105. The axialmovement of the valve piston 216 may cause one or more of the fluidports 129 in the valve piston 216 to move in or out of alignment withone or more of the fluid ports 140 in the valve housing 144 whichprovides fluid communication with the annular chamber 345 (FIGS. 3-5).When the pin 1700 is in the first upper hooked portion 1708, as shown inFIG. 12B, the fluid ports 129, 140 may be misaligned. This correspondsto the locked closed position of the expandable apparatus 100 as shownin FIG. 4. In the locked closed position, the blades will be in theretracted position so long as there is a flow of fluid high enough toovercome the force of the spring 134.

In order to align the fluid ports 129, 140, according to the embodimentof FIGS. 12A-12C, the drilling fluid pressure may be reduced oreliminated, causing the valve piston 216 to move upward in response tothe force of the second spring 134. As the valve piston 216 is biasedupward, it moves relative to the pin 1700 carried by the valve housing144 until the pin 1700 comes into contact with a lower angled sidewall1710 of the pin track 1702. The lower angled sidewall 1710 continues tomove along the pin 1700 until the pin 1700 sits (not shown) in a secondlower hooked portion 1712. As the lower angled sidewall 1710 of the pintrack 1702 moves along the pin 1700, the valve piston 216 is againforced to rotate. When the drilling fluid is again flowed and the fluidpressure is again increased, the valve piston 216 biases downward andthe pin track 1702 moves along the pin 1700 until the pin 1700 comesinto contact with the upper angled sidewall 1714 of the track 1705. Theupper angled sidewall 1714 of track 1705 moves along the pin 1700 untilthe pin 1700 sits in a second upper hooked portion 1716 as shown in FIG.12C. As the upper angled sidewall 1714 of the pin track 1702 moves withrespect to pin 1700, the valve piston 216 is forced to rotate stillfurther within the valve housing 144. This axial movement causes thefluid ports 129, 140 to align with one another, allowing drilling fluidto flow into the annular chamber 345 and sliding the push sleeve 215 asdescribed above. This corresponds to the locked open position of theexpandable apparatus 100 illustrated in FIG. 5. In the locked openposition, the blades will be in the extended position so long as thereis a flow of fluid high enough to overcome the force of the spring 134.The track 1705 may be capable of repeating itself once the pin 1700 hastraveled around a circumference of the track 1705. Similarly, when morethan one pin 1700 is utilized, each pin 1700 may have a mirrored track(i.e., radially symmetric) such that each of the neutral, locked open,and locked closed positions may be achieved.

It will be apparent that the valve as embodied according to any of thevarious embodiments described above may be opened and closed repeatedlyby simply reducing the flow rate of the drilling fluid and againincreasing the flow rate of the drilling fluid to cause the valve piston216 to move upward and downward, resulting in the rotational and axialdisplacement described above due to the pin and track arrangement.Additionally, other embodiments of valves for controlling the flow offluid to the annular chamber 345 (FIGS. 3-5) may also be used.

In view of the foregoing, expandable apparatuses of various embodimentsof the disclosure may be expanded and contracted by an operator anunlimited number of times. As the condition of the expandable apparatusmay change multiple times while downhole, it may be especially importantto be able to reliably detect the operating condition of the expandableapparatus.

In some embodiments, as previously discussed and as shown in FIGS.12A-12C, a nozzle 202 having a restricted cross-sectional area may becoupled to the valve piston 216. As shown in FIG. 12C, the nozzle 202may include at least one fluid port 1800 extending through a sidewall ofthe nozzle 202. When the expandable apparatus 100 is in the neutral orlocked closed position as shown in FIGS. 12A and 12B, the nozzle 202 isretained within the valve housing 144. Accordingly, at leastsubstantially no fluid may pass through the at least one fluid port 1800when the expandable apparatus 100 is in the neutral or locked closedpositions. However, as shown in FIG. 12C, when the expandable apparatus100 is in the locked open position, the nozzle 202 extends beyond an endof the valve housing 144. This allows fluid to pass through the at leastone fluid port 1800 in the nozzle 202, thereby increasing an areaavailable for fluid flow which may result in a visible pressure drop ofthe drilling fluid passing through the expandable apparatus 100.Accordingly, by detecting and/or monitoring variations of pressure ofthe drilling fluid caused by the availability of fluid flow through theat least one fluid port 1800 in the nozzle, a position of the valvepiston 216 may be determined, and, hence, a position of the blades maybe determined.

In at least some embodiments, as previously discussed, it may bedesirable to prevent debris and other particles from entering theannular fluid chamber 345. Accordingly, in some embodiments, a screen1900 may be placed over at least the at least one fluid port 129 of thevalve piston 216, located between the valve piston 216 and the valvehousing 144, as shown in FIGS. 14A and 14B. The screen 1900 may inhibitthe flow of solid materials through the at least one fluid port 129 thatmay plug at least one of the at least one fluid port, the one or morepressure relief nozzles, or both. In some embodiments, the screen 1900may comprise a cylindrical sleeve extending circumferentially around thevalve piston 216.

The openings within the screen 1900 may be small enough to prevent soliddebris in the drilling fluid from entering the annular chamber 345. Forexample, in some embodiments, the openings within the screen 1900 mayhave a width less than about five hundredths of an inch (0.05″). Infurther embodiments, the openings within the screen 1900 may have awidth less than about fifteen thousandths of an inch (0.015″). Duringdrilling, a velocity of the drilling fluid may act to clean screen 1900,preventing plugging of the screen 1900.

In some embodiments, the expandable apparatus 100 may include at leastone bonded seal to prevent fluid from entering the annular chamber 345except for when the expandable apparatus 100 is in the locked openposition (see FIGS. 5 and 12C). For example, as shown in FIG. 3, a firstseal 1902 and a second seal 1904 of the expandable apparatus 100 may bebonded seals. The first seal 1902 may be located between the upperportion 146 and the lower portion 148 of the valve housing 144 andprovide a seal between the valve housing 144 and the valve piston 216.The second seal 1904 may be located on the nozzle 202 coupled to thevalve piston 216 and provide a seal between the nozzle 202 and valvehousing 144. The seals 1902, 1904 may include a metal ring or gaskethaving a rectangular section with at least one opening. An elastomericring is fit within the opening within the metal ring and bonded thereto.The disruption of the elastomeric ring is resisted by the metal ringwhich limits the deformation of the elastomeric ring. Conventionalseals, such as plastic or O-ring seals, may be damaged or lost atpressures and conditions experienced during operation of the expandableapparatus 100. By replacing such conventional seals with bonded seals,the seals 1902, 1904 are more likely to withstand the operatingconditions and pressures of the expandable apparatus 100.

In further embodiments, the expandable apparatus 100 may include atleast one chevron seal, as shown in FIGS. 14A and 14B, to prevent fluidfrom entering the annular chamber 345 except for when the expandableapparatus 100 is in the locked open position (see FIGS. 5 and 12C). Forexample, a first seal 1902 and a second seal 1904 of the expandableapparatus 100 may include a chevron seal assembly 1906. The chevron sealassembly 1906 may include a chevron seal 1908, a first chevron backupring 1910, a second chevron backup ring 1912, a first adaptor 1914, anda second adaptor 1916. The chevron seal 1908 may have a cross-sectionshaped generally as a chevron or “V” shape. Similarly, the first andsecond chevron backup rings 1910 and 1912 may have a cross-sectionshaped generally as a chevron or “V” shape. The first and secondadaptors 1914 and 1916 may be shaped to adapt the assembled chevron seal1908 and first and second chevron backup rings 1910 and 1912 to fitsnugly in a seal gland 1918. By replacing such conventional seals withchevron seals, the seals 1902, 1904 are more likely to withstand theoperating conditions and pressures of the expandable apparatus 100. Asshown in FIG. 14A, when the fluid port 129 is located on a first side ofthe chevron seal assembly 1906 the chevron seal assembly 1906 mayprevent fluid communication between the fluid port 129 of the valvepiston 216 and the fluid port 140 of the valve housing 144. As shown inFIG. 14B, when the fluid port 129 travels past the chevron seal assembly1906 the fluid ports 129 and 140 may be aligned and in fluidcommunication. When the fluid port 129 of the valve piston moves pastthe chevron seal assembly 1906, the fluid within the fluid port 129 maybe under pressure and the chevron seal assembly 1906 may be exposed tothis pressurized fluid. Chevron seal assemblies 1906 may provide areliable seal in such a location and may have an improved seal liferelative to conventional seals.

FIG. 15 is an enlarged view of the bottom portion 12 of an expandableapparatus 2100 according to an additional embodiment, which includes astatus indicator 2200 to facilitate the remote detection of theoperating condition of the expandable apparatus 2100. As shown in FIGS.15 and 16, the valve piston 2128 may include a nozzle 2202 coupled to abottom end 2204 of the valve piston 2128. While the following examplesrefer to a position of the nozzle 2202 within the tubular body 2108, itis understood that in some embodiments the nozzle 2202 may be omitted.For example, in some embodiments, a status indicator 2200, as describedin detail herein, may be used to generate a signal indicative of aposition of a bottom end 2204 of the valve piston 2128 relative to thestatus indicator 2200. For example, the signal may comprise a pressuresignal in the form of, for example, a detectable or measurable pressureor change in pressure of drilling fluid within the standpipe. As shownin FIG. 15, the status indicator 2200 may be coupled to the lowerportion 2148 of the valve housing 2144. The status indicator 2200 isconfigured to indicate the position of the nozzle 2202 relative to thestatus indicator 2200 to persons operating the drilling system. Becausethe nozzle 2202 is coupled to the valve piston 2128, the position of thenozzle 2202 also indicates the position of the valve piston 2128 and,thereby, the intended and expected positions of push sleeve 2115 and theblades 120, 125, 130 (FIG. 2). If the status indicator 2200 indicatesthat the nozzle 2202 is not over the status indicator 2200, as shown inFIG. 15, then the status indicator 2200 effectively indicates that theblades are, or at least should be, retracted. If the status indicator2200 indicates that the nozzle 2202 is over the status indicator 2200,as shown in FIG. 16, then the status indicator 2200 effectivelyindicates that the expandable apparatus 2100 is in an extended position.

FIG. 17 is an enlarged view of one embodiment of the status indicator2200 when the expandable apparatus 2100 is in the closed position. Insome embodiments, the status indicator 2200 includes at least twoportions, each portion of the at least two portions having a differentcross-sectional area in a plane perpendicular to the longitudinal axisL. For example, in one embodiment, as illustrated in FIG. 17, the statusindicator 2200 includes a first portion 2206 having a firstcross-sectional area 2212, a second portion 2208 having a secondcross-sectional area 2214, and a third portion 2210 having a thirdcross-sectional area 2216. As shown in FIG. 17, the firstcross-sectional area 2212 is smaller than the second cross-sectionalarea 2214, the second cross-sectional area 2214 is larger than the thirdcross-sectional area 2216, and the third cross-sectional area 2216 islarger than the first cross-sectional area 2212. The differentcross-sectional areas 2212, 2214, 2216 of the status indicator 2200 ofFIG. 17 are non-limiting examples, any combination of differingcross-sectional areas may be used. For example, in the status indicator2200 having three portions 2206, 2208, 2210, as illustrated in FIG. 17,additional embodiments of the following relative cross-sectional areasmay include: the first cross-sectional area 2212 may be larger than thesecond cross-sectional area 2214 and the second cross-sectional area2214 may be smaller than the third cross-sectional area 2216 (see, e.g.,FIG. 19); the first cross-sectional area 2212 may be smaller than thesecond cross-sectional area 2214 and the second cross sectional area2214 may be smaller than the third cross-sectional area 2216 (see, e.g.,FIG. 20); the first cross-sectional area 2212 may be larger than thesecond cross-sectional area 2214 and the second cross sectional area2214 may be larger than the third cross-sectional area 2216 (see, e.g.,FIG. 21). In addition, the transition between cross-sectional areas2212, 2214, 2216 may be gradual as shown in FIG. 17, or the transitionbetween cross-sectional areas 2212, 2214, 2216 may be abrupt as shown inFIG. 19. A length of each portion 2206, 2208, 2210 (in a directionparallel to the longitudinal axis L (FIG. 1)) may be substantially equalas shown in FIGS. 19-21, or the portions 2206, 2208, 2210 may havedifferent lengths as shown in FIG. 22. The embodiments of statusindicators 2200 shown in FIGS. 17 and 19-22 are non-limiting examples,and any geometry or configuration having at least two differentcross-sectional areas may be used to form the status indicator 2200.

In further embodiments, the status indicator 2200 may comprise only onecross-sectional area, such as a rod as illustrated in FIG. 23. If thestatus indicator 2200 comprises a single cross-sectional area, thestatus indicator 2200 may be completely outside of the nozzle 2202 whenthe valve piston 2128 is in the initial proximal position and the bladesare in the retracted positions.

Continuing to refer to FIG. 17, the status indicator 2200 may alsoinclude a base 2220. The base 2220 may include a plurality of fluidpassageways 2222 in the form of holes or slots extending through thebase 2220, which allow the drilling fluid to pass longitudinally throughthe base 2220. The base 2220 of the status indicator 2200 may beattached to the lower portion 2148 of the valve housing 2144 in such amanner as to fix the status indicator 2200 at a location relative to thevalve housing 2144. In some embodiments, the base 2220 of the statusindicator may be removably coupled to the lower portion 2148 of thevalve housing 2144. For example, each of the base 2220 of the statusindicator 2200 and the lower portion 2148 of the valve housing 2144 mayinclude a complementary set of threads (not shown) for connecting thestatus indicator 2200 to the lower portion 2148 of the valve housing2144. In some embodiments, the lower portion 2148 may comprise anannular recess 2218 configured to receive an annular protrusion formedon the base 2220 of the status indicator 2200. At least one of thestatus indicator 2200 and the lower portion 2148 of the valve housing2144 may be formed of an erosion resistant material. For example, insome embodiments, the status indicator 2200 may comprise a hardmaterial, such as a carbide material (e.g., a cobalt-cemented tungstencarbide material), or a nitrided or case hardened steel.

The nozzle 2202 may be configured to pass over the status indicator 2200as the valve piston 2128 moves from the initial proximal position into adifferent distal position to cause extension of the blades. FIG. 18illustrates the nozzle 2202 over the status indicator 2200 when thevalve piston 2128 is in the distal position for extension of the blades.In some embodiments, the fluid passageway 2192 extending through thenozzle 2202 may have a uniform cross-section. Alternatively, as shown inFIGS. 17 and 18, the nozzle 2202 may include a protrusion 2224 which isa minimum cross-sectional area of the fluid passageway 2192 extendingthrough the nozzle 2202.

In operation, as fluid is pumped through the internal fluid passageway2192 extending through the nozzle 2202, a pressure of the drilling fluidwithin the drill string or the bottom hole assembly (e.g., within thereamer apparatus 2100) may be measured and monitored by personnel orequipment operating the drilling system. As the valve piston 2128 movesfrom the initial proximal position to the subsequent distal position,the nozzle will move over at least a portion of the status indicator2200, which will cause the fluid pressure of the drilling fluid beingmonitored to vary. These variances in the pressure of the drilling fluidcan be used to determine the relationship of the nozzle 2202 to thestatus indicator 2200, which, in turn, indicates whether the valvepiston 2128 is in the proximal position or the distal position, andwhether the blades should be in the retracted position or the extendedposition.

For example, as shown in FIG. 17, the first portion 2206 of the statusindicator 2200 may be disposed within nozzle 2202 when the valve piston2128 is in the initial proximal position. The pressure of the fluidtraveling through the internal fluid passageway 2192 may be a functionof the minimum cross-sectional area of the fluid passageway 2192 throughwhich the drilling fluid is flowing through the nozzle 2102. In otherwords, as the fluid flows through the nozzle 2102, the fluid must passthrough an annular-shaped space defined by the inner surface of thenozzle 2202 and the outer surface of the status indicator 2200. Thisannular-shaped space may have a minimum cross-sectional area equal tothe minimum of the difference between the cross-sectional area of thefluid passageway 2192 through the nozzle 2202 and the cross-sectionalarea of the status indicator 2200 disposed within the nozzle 202 (in acommon plane transverse to the longitudinal axis L). Because the crosssectional area 2214 of the second portion 2208 of the status indicator2200 differs from the cross-sectional area 2212 of the first portion2206, the pressure of the drilling fluid will change as the nozzle 2202passes from the first portion 2206 to the second portion 2208 of thestatus indicator 2200. Similarly, because the cross sectional area 2214of the second portion 2208 of the status indicator 2200 differs from thecross-sectional area 2216 of the third portion 2210 of the statusindicator 2200, the pressure of the drilling fluid will change as thenozzle 2202 passes from the second portion 2208 to the third portion2210.

FIG. 24 is a simplified graph of the pressure P of drilling fluid withinthe valve piston 2128 as a function of a distance X by which the valvepiston 2128 travels as it moves from the initial proximal position tothe subsequent distal position while the drilling fluid is flowingthrough the valve piston 2128. With continued reference to FIG. 24, forthe status indicator 2200 illustrated in FIGS. 17 and 18, a firstpressure P₁ may be observed the first portion 2206 of the statusindicator 2200 is within the nozzle 2202 as shown in FIG. 17. As theexpandable apparatus 2100 moves from the closed to the open positionvalve piston 2128 moves from the initial proximal position shown in FIG.17 to the subsequent distal position shown in FIG. 18, a visiblepressure spike corresponding to a second pressure P₂ will be observed asthe protrusion 2224 of the nozzle 2202 passes over the second portion2208 of the status indicator 2200. For example, when the valve piston2128 has traveled a first distance X₁, the protrusion 2224 will reachthe transition between the first portion 2206 and the second portion2208 of the status indicator 2200, and the pressure will then increasefrom the first pressure P₁ to an elevated pressure P₂, which is higherthan P₁. When the valve piston 2128 has traveled a second, fartherdistance X, the protrusion 2224 will reach the transition between thesecond portion 2208 and the third portion 2210 of the status indicator2200, and the pressure will then decrease from the second pressure P₂ toa lower pressure P₃, which is lower than P₂. The third pressure P3 maybe higher than the first pressure P in some embodiments of theinvention, although the third pressure P₃ could be equal to or less thanthe first pressure P₁ in additional embodiments of the invention. Bydetecting and/or monitoring the variations in the pressure within thevalve piston 2128 (or at other locations within the drill string orbottom hole assembly) caused by relative movement between the nozzle2202 and the status indicator 2200, the position of the valve piston2128 may be determined, and, hence, the position of the blades may bedetermined.

For example, in one embodiment, the status indicator 2200 may be atleast substantially cylindrical. The second portion 2208 may have adiameter about equal to about three times a diameter of the firstportion 2206 and the third portion 2210 may have a diameter about equalto about the diameter of the first portion 2206. For example, in oneembodiment, as illustrative only, the first portion 2206 may have adiameter of about one half inch (0.5″), the second portion 2208 may havea diameter of about one and forty-seven hundredths of an inch (1.47″)and the third portion 2210 may have a diameter of about eight tenths ofan inch (0.80″). At an initial fluid flow rate of about six hundredgallons per minute (600 gpm) for a given fluid density, the firstportion 2206 within the nozzle 2202 generates a first pressure dropacross the nozzle 2202 and the status indicator 2200. In someembodiments, the first pressure drop may be less than about 100 psi. Thefluid flow rate may then be increased to about eight hundred gallons perminute (800 gpm), which generates a second pressure drop across thenozzle 2202 and the status indicator 2200. The second pressure drop maybe greater than about one hundred pounds per square inch (100 psi), forexample, the second pressure drop may be about one hundred and thirtypounds per square inch (130 psi). At 800 gpm, the valve piston 2128begins to move toward the distal end 2190 (FIG. 15) of the expandableapparatus 2100 causing the protrusion 2224 of the nozzle 2202 to passover the status indicator 2200. As the protrusion 2224 of the nozzle2202 passes over the second portion 2208 of the status indicator 2200,the cross-sectional area available for fluid flow dramaticallydecreases, causing a noticeable spike in the pressure drop across thenozzle 2202 and the status indicator 2200. The magnitude of the pressuredrop may peak at, for example, about 500 psi or more, about 750 psi ormore, or even about 1,000 psi or more (e.g., about one thousand twohundred and seventy-three pounds per square inch (1273 psi)). As theprotrusion 2224 of the nozzle 2202 continues to a position over thethird portion 2210 of the status indicator 2200, the pressure drop maydecrease to a third pressure drop. The third pressure drop may begreater than the second pressure drop but less than the pressure peak.For example, the third pressure drop may be about one hundred fiftypounds per square inch (150 psi).

As previously mentioned, in some embodiments, the status indicator 2200may include a single uniform cross-sectional area as shown in FIG. 23.In this embodiment, only a single increase in pressure may be observedas the nozzle 2202 passes over the status indicator 2200. Accordingly,the more variations in cross-sectional area the status indicator 2200,such as two or more cross-sectional areas, the greater the accuracy oflocation of the nozzle 2202 that may be determined.

In yet further embodiments, the status indicator 2200 may completelyclose the nozzle 2202 and prevent fluid flow through the nozzle 2202 atthe conclusion of the when valve piston is in the distal position andthe blades 120, 125, 130 (FIG. 2) have been moved to a fully expandedposition. In view of this, a significant increase in the standpipepressure may be achieved and a specific pressure, or a change inpressure, may then be detected to signal to an operator that the blades120, 125, 130 have moved to an expanded position. For example, thestatus indicator may be configured generally as shown in FIG. 19 and mayhave a third portion 2210 having a shape sized and shaped to seal thenozzle 2202 when the nozzle 2202 extends over the third portion 2210.After the blades 120, 125, 130 of the expandable apparatus 2100 havemoved to an expanded position and the nozzle 2202 has been closed, theincrease in pressure will be detected by a pressure sensor and theoperator may be alerted and may then adjust the fluid flow to achieve anappropriate operating pressure.

Furthermore, although the expandable apparatus described herein includesa valve piston, the status indicator 2200 may also be used in otherexpandable apparatuses as known in the art.

Although the forgoing disclosure illustrates embodiments of anexpandable apparatus comprising an expandable reamer apparatus, thedisclosure is not so limited. For example, in accordance with otherembodiments of the disclosure, the expandable apparatus may comprise anexpandable stabilizer, wherein the one or more expandable features maycomprise stabilizer blocks. Thus, while certain embodiments have beendescribed and shown in the accompanying drawings, such embodiments aremerely illustrative and not restrictive of the scope of the invention,and this invention is not limited to the specific constructions andarrangements shown and described, since various other additions andmodifications to, and deletions from, the described embodiments will beapparent to one of ordinary skill in the art.

Additionally, features from embodiments of the disclosure may becombined with features of other embodiments of the disclosure and mayalso be combined with and included in other expandable devices. Thescope of the invention is, accordingly, limited only by the claims whichfollow herein, and legal equivalents thereof.

What is claimed is:
 1. An expandable apparatus, comprising: a tubularbody comprising a fluid passageway extending therethrough and firstnozzles extending through the tubular body; a valve housing disposedwithin the tubular body, the valve housing comprising a fluid portopening into an annular chamber disposed between the valve housing andthe tubular body; a valve piston disposed within the valve housing, thevalve piston comprising a surface configured to move the valve pistonaxially responsive to drilling fluid pressure and a second nozzleconfigured to selectively align and misalign with the port of the valvehousing, the valve piston configured to move axially relative to thetubular body from a first, neutral position to a second, locked openposition responsive to a pressure of drilling fluid passing through thefluid passageway to exert a force on the surface, wherein the secondnozzle is misaligned with the fluid port when the valve piston is in thefirst, neutral position and the second nozzle is aligned with the fluidport when the valve piston is in the second, locked open position; and apush sleeve disposed within the tubular body and coupled to at least oneexpandable feature, the push sleeve configured to move axiallyresponsive to the flow of fluid into the annular chamber and extend theat least one expandable feature, the push sleeve comprising nozzle portsextending through the push sleeve to provide fluid communication withthe first nozzles, wherein the first nozzles and the nozzle ports arealways open, wherein the at least one expandable feature is in aretracted position when the valve piston is in the first, neutralposition and is movable to an extended position when the valve piston isin the second, locked open position.
 2. The expandable apparatus ofclaim 1, wherein the second nozzle comprises at least one fluid apertureextending through a sidewall of the valve piston.
 3. The expandableapparatus of claim 2 further comprising at least one screen extendingover the at least one fluid aperture of the valve piston.
 4. Theexpandable apparatus of claim 1, wherein the expandable apparatuscomprises at least one of a bonded seal and a chevron seal.
 5. Theexpandable apparatus of claim 1, wherein the annular chamber comprisesat least one bleed nozzle or check valve, wherein the at least one bleednozzle or check valve is always open.
 6. The expandable apparatus ofclaim 1, wherein the valve piston is further configured to move axiallyrelative to the tubular body from the second, locked open position to athird, locked closed position between the first, neutral position andthe second, locked open position, and wherein the at least oneexpandable feature is in the retracted position when the valve piston isin the third, locked closed position.
 7. The expandable apparatus ofclaim 1, further comprising at least one biasing element configured anddisposed to exert an axial bias force on the valve piston.
 8. Theexpandable apparatus of claim 7, wherein the valve piston is coupled tothe valve housing by at least one pin carried by one of the valve pistonand the valve housing, the at least one pin engaged with a track locatedin the other of the valve piston and the valve housing, the at least onepin and the track, in combination, configured to control rotational andaxial movement of the valve piston within and relative to the valvehousing responsive to the upward bias force of the biasing element andselected application of an axial, downward force provided by drillingfluid flow through the fluid passageway of the valve piston.
 9. A methodof operating an expandable apparatus, comprising: positioning anexpandable apparatus in a borehole; directing a fluid flow through afluid passageway of a tubular body of the expandable apparatus, whereina valve housing is disposed within the tubular body to define an annularchamber between the valve housing and the tubular body; moving a valvepiston within the valve housing axially relative to the tubular bodyfrom a first, neutral position to a second, locked open position inresponse to fluid flow exerting a force against a surface of the valvepiston to unobstruct a fluid port in the valve housing; aligning a firstnozzle of the valve piston with the fluid port of the valve housingresponsive to moving the valve piston; directing at least a portion ofthe fluid flow aligning the first nozzle and the fluid port into theannular chamber; moving a push sleeve axially relative to the tubularbody with the fluid flow directed into the annular chamber between thevalve housing and the tubular body; extending at least one expandablefeature coupled to the push sleeve in response to movement of the pushsleeve; and directing a fluid flow through nozzle ports extendingthrough the push sleeve to second nozzles extending through the tubularbody when the at least one expandable feature is extended and when theat least one expandable feature is retracted.
 10. The method of claim 9,wherein directing the at least a portion of the fluid flow through thefirst nozzle and the fluid port into the annular chamber comprisesdirecting the fluid flow through the first nozzle comprising at leastone aperture extending through a sidewall of the valve piston, the fluidport extending through a sidewall of the valve housing into the annularchamber.
 11. The method of claim 10, further comprising directing thefluid flow through the at least one fluid aperture when the at least oneexpandable feature is extended.
 12. The method of claim 11, furthercomprising directing the fluid flow through at least one screenextending over the at least one aperture.
 13. The method of claim 9,further comprising providing a seal between the valve piston and thetubular body with at least one of a bonded seal and a chevron seal. 14.The method of claim 9, further comprising directing a fluid flow fromthe annular chamber through at least one bleed nozzle or check valve.15. The method of claim 9, further comprising moving the valve pistonfrom the second, locked open position to a third, locked closed positionbetween the first, neutral position and the second, locked openposition, wherein the at least one expandable feature is in a retractedposition when the valve piston is in the third, locked closed position.16. The method of claim 9, further comprising exerting an axial biasforce on the valve piston.
 17. The method of claim 9, further comprisingrepeatedly extending and retracting the at least one expandable featurewhile the expandable apparatus is in the borehole.